Method of developing subsurface barriers

ABSTRACT

A method and apparatus for construction of a subsurface barrier for the recovery of petroleum fluids from the subsurface by steam and/or solvent injection. Multiple propped vertical inclusions at various azimuths and depths are constructed from multiple wells so that the inclusions intersect and coalesce. The inclusions are made impermeable by a variety of means including the proppant swelling to fill the voids of the inclusions. The proppant includes ceramic beads coated with an electrically conductive and heat hardenable resin. The resin is electrically heated and flows to fill the voids in the inclusions as the resin hardens. The proppant includes sand or ceramic beads that are subject to cold saline water circulated between the wells to freeze the formation pore water. The proppant includes low viscosity grout that is injected with a time delay setting agent or electrically conductive grout that is heated and set by electric current passing through the grout.

TECHNICAL FIELD

The present invention generally relates to enhanced recovery of petroleum fluids from the subsurface by steam injection, in which a nearby outcrop or depleted steam chamber causes loss of steam from the active process zone or requires reducing the steam pressure in the active process zone to minimize water loss. A barrier between the process zone and the outcrop or depleted chamber, enables the enhanced recovery process to be more efficient, more economical, minimizes water usage and results in increased production of petroleum fluids from the subsurface formation.

BACKGROUND OF THE INVENTION

Heavy oil and bitumen oil sands are abundant in reservoirs in many parts of the world such as those in Alberta, Canada, Utah and California in the United States, the Orinoco Belt of Venezuela, Indonesia, China and Russia. The hydrocarbon reserves of the oil sand deposit is extremely large in the trillions of barrels, with recoverable reserves estimated by current technology in the 300 billion barrels for Alberta, Canada and a similar recoverable reserve for Venezuela. These vast heavy oil (defined as the liquid petroleum resource of less than 20° API gravity) deposits are found largely in unconsolidated sandstones, being high porosity permeable cohensionless sands with minimal grain to grain cementation. The hydrocarbons are extracted from the oils sands either by mining or in situ methods.

The heavy oil and bitumen in the oil sand deposits have high viscosity at reservoir temperatures and pressures. While some distinctions have arisen between tar or oil sands, bitumen and heavy oil, these terms will be used interchangeably herein. The oil sand deposits in Alberta, Canada extend over many square miles and vary in thickness up to hundreds of feet thick. Although some of these deposits lie close to the surface and are suitable for surface mining, the majority of the deposits are at depth ranging from a shallow depth of 150 feet down to several thousands of feet below ground surface. The oil sands located at these depths constitute some of the world's largest presently known petroleum deposits. The oil sands contain a viscous hydrocarbon material, commonly referred to as bitumen, in an amount that ranges up to 15% by weight. Bitumen is effectively immobile at typical reservoir temperatures. For example at 15° C., bitumen has a viscosity of ˜1,000,000 centipoise. However at elevated temperatures the bitumen viscosity changes considerably to be ˜350 centipoise at 100° C. down to ˜10 centipoise at 180° C. The oil sand deposits have an inherently high permeability ranging from ˜1 to 10 Darcy, thus upon heating, the heavy oil becomes mobile and can easily drain from the deposit.

It is well known that extensive heavy oil reservoirs are found in formations comprising unconsolidated, weakly cemented sediments. Unfortunately, the methods currently used for extracting the heavy oil from these formations require the injection of steam under pressure, such as SAGD (Steam Assisted Gravity Drainage), and as such are difficult and often uneconomic if the SAGD well pairs are located in proximity to an outcrop or depleted low pressure steam chambers. Even though the formations contain significant quantities of heavy oil and bitumen, which is basically immobile at initial reservoir conditions, the pore water saturation and permeability of the formation gives rise to reasonably high water mobility. Lean zones within the formation only greatly increase the water mobility, thus giving rise to the need for a barrier to provide a more efficient, less environmental impact and more cost effective recovery system. Operating a SAGD steam chamber at lower pressure gives rise to higher steam oil ratios (SORs) but even more significantly at low steam pressures, the steam may not be able to penetrate horizontal shale layers and thus restrict the height of the steam chamber, giving rise to higher SORs and a significant impact on production. Such impacts can have a significant effect on the overall economics of the SAGD process.

Descriptions of the SAGD process and modifications are described in U.S. Pat. No. 4,344,485 to Butler, and U.S. Pat. No. 5,215,146 to Sanchez and thermal extraction methods in U.S. Pat. No. 4,085,803 to Butler, U.S. Pat. No. 4,099,570 to Vandergrift, and U.S. Pat. No. 4,116,275 to Butler et al. The SAGD process consists of two horizontal wells at the bottom of the hydrocarbon formation, with the injector well located approximately 10-15 feet vertically above the producer well. The steam injection pressures exceed the formation fracturing pressure in order to establish connection between the two wells and develop a steam chamber in the oil sand formation. Similar to CSS (Cyclic Steam Stimulation), the SAGD) method has complications, albeit less severe than CSS, due to the lack of steam flow control along the long section of the horizontal well and the difficulty of controlling the growth of the steam chamber.

Thermal recovery processes using steam require large amounts of energy to produce the steam, using either natural gas or heavy fractions of produced synthetic crude. Burning these fuels generates significant quantities of greenhouse gases, such as carbon dioxide. Also, the steam process uses considerable quantities of water, which even though may be reprocessed, involves recycling costs and energy use. With impermeable barriers in place near outcrops and/or to isolate active steaming operations from depleted steam chambers, the SAGD system will be a less energy intensive oil recovery process and will also minimize water usage.

Solvents applied to the bitumen soften the bitumen and reduce its viscosity and provide a non-thermal mechanism to improve the bitumen mobility. Hydrocarbon solvents consist of vaporized light hydrocarbons such as ethane, propane or butane or liquid solvents such as pipeline diluents, natural condensate streams or fractions of synthetic crudes. The diluent can be added to steam and flashed to a vapor state or be maintained as a liquid at elevated temperature and pressure, depending on the particular diluent composition. While in contact with the bitumen, the saturated solvent vapor dissolves into the bitumen. This diffusion process is due to the partial pressure difference in the saturated solvent vapor and the bitumen. As a result of the diffusion of the solvent into the bitumen, the oil in the bitumen becomes diluted and mobile and will flow under gravity. The resultant mobile oil may be deasphalted by the condensed solvent, leaving the heavy asphaltenes behind within the oil sand pore space with little loss of inherent fluid mobility in the oil sands due to the small weight percent (5-15%) of the asphaltene fraction to the original oil in place. Deasphalting the oil from the oil sands produces a high grade quality product by 3°-5° API gravity. If the reservoir temperature is elevated the diffusion rate of the solvent into the bitumen is raised considerably being two orders of magnitude greater at 100° C. compared to ambient reservoir temperatures of ˜15° C.

Solvent assisted recovery of hydrocarbons in continuous and cyclic modes are described including the VAPEX process and combinations of steam and solvent plus heat. See U.S. Pat. No. 4,450,913 to Allen et al, U.S. Pat. No. 4,513,819 to Islip et al, U.S. Pat. No. 5,407,009 to Butler et al, U.S. Pat. No. 5,607,016 to Butler, U.S. Pat. No. 5,899,274 to Frauenfeld et al, U.S. Pat. No. 6,318,464 to Mokrys, U.S. Pat. No. 6,769,486 to Lim et al, and U.S. Pat. No. 6,883,607 to Nenniger et al. The VAPEX process generally consists of two horizontal wells in a similar configuration to SAGD; however, there are variations to this including spaced horizontal wells and a combination of horizontal and vertical wells. The startup phase for the VAPEX process can be lengthy and take many months to develop a controlled connection between the two wells and avoid premature short circuiting between the injector and producer. The VAPEX process with horizontal wells has similar issues to CSS and SAGD in horizontal wells, due to the lack of solvent flow control along the long horizontal well bore, which can lead to non-uniformity of the vapor chamber development and growth along the horizontal well bore.

The thermal and solvent methods of enhanced oil recovery from oil sands, all suffer from a lack of surface area access to the in place bitumen. Thus the reasons for raising steam pressures above the fracturing pressure in CSS and during steam chamber development in SAGD, are to increase surface area of the steam with the in place bitumen. Similarly the VAPEX process is limited by the available surface area to the in place bitumen, because the diffusion process at this contact controls the rate of softening of the bitumen. Likewise during steam chamber growth in the SAGD process the contact surface area with the in place bitumen is virtually a constant, thus limiting the rate of heating of the bitumen. Therefore both methods (heat and solvent) or a combination thereof would greatly benefit from a substantial increase in contact surface area with the in place bitumen. Hydraulic fracturing of low permeable reservoirs has been used to increase the efficiency of such processes and CSS methods involving fracturing are described in U.S. Pat. No. 3,739,852 to Woods et al, U.S. Pat. No. 5,297,626 to Vinegar et al, and U.S. Pat. No. 5,392,854 to Vinegar et al. Also during initiation of the SAGD process overpressurized conditions are usually imposed to accelerate the steam chamber development, followed by a prolonged period of underpressurized condition to reduce the steam to oil ratio.

Electrical resistive heating of oil shale and oil sand formations utilizing a hydraulic fracture filled with an electrically conductive material are described in U.S. Pat. No. 3,137,347 to Parker, involving a horizontal hydraulic fracture filled with conductive proppant and with the use of two (2) wells to electrically energizing the fracture and raise the temperature of the oil shale to pyrolyze the organic matter and produce hydrocarbon from a third well, in U.S. Pat. No. 5,620,049 to Gipson et al. with a single well configuration in a hydrocarbon formation predominantly a vertical fracture filled with conductive temperature setting resin coated proppant and the electric current passes through the conductive proppant to a surface ground and the single well is completed to raise the temperature of the oil in-situ to reduce its viscosity and produce hydrocarbons from the same well, in U.S. Pat. No. 6,148,911 to Gipson et al. with a single well configuration in a gas hydrate formation with predominantly a horizontal fracture filled with conductive proppant and the electric current passes through the conductive proppant to a surface ground, raising the temperature of the formation to release the methane from the gas hydrates and the single well is completed for methane production, in U.S. Pat. No. 7,331,385 to Symington et al. in U.S. Pat. No. 7,631,691 to Symington et al. and in Canadian Patent No. 2,738,873 to Symington et al. all with a predominantly vertical fracture filled with conductive proppant and the conductive fracture is electrically energized by contact with at least two (2) wells or in the case of a single well presumably through the well and surface ground with the oil shale raised to a temperature to pyrolyze the organic matter into producible hydrocarbons, with the electrically conductive fracture composed of electrically conductive proppant and non-electrically conductive non-permeable cement. The single well systems described above all suffer from low efficiency and high energy loss due to the current passes through a significant distance of the formation from the conductive fracture to the surface ground. Also the systems with two or more wellbores do not disclosed how the electrode to conductive fracture contact will be other than a point contact resulting in significant energy loss and overheating at such a contact. The above referenced methods describe the use of hydraulic fracturing in its conventional sense, and such application of hydraulic fracturing of brittle rock to form fractures therein are typically not applicable to ductile formations comprising unconsolidated, weakly cemented sediments.

Construction of hydraulic barriers by jet grouting, freezing, sheet piling, etc are common in civil and mining applications but are generally not suitable or economic at depth. Hydraulic barriers as conformance systems are common in the petroleum field, such as sodium silicate grouts, microbial barriers, swelling particles, etc but are intended for sealing zones around boreholes and not intended for barriers kilometers in length and for the need to be continuous. Microbial barriers suffer from the disadvantage that they require constant nutrient feeding, but also are only applicable over modest temperature ranges.

Numerous barriers systems have been described in many patents for application to the in-situ retorting of oil shale and tar or oil sands, see U.S. Pat. No. 7,032,660 to Vinegar et al., U.S. Pat. No. 7,077,198 to Vinegar et al., U.S. Pat. No. 7,516,787 to Kaminsky, U.S. Pat. No. 7,527,094 to McKinzie et al., U.S. Pat. No. 7,546,873 to Kim et al., U.S. Pat. No. 7,647,972 to Kaminsky, U.S. Pat. No. 7,703,513 to Vinegar et al. and Canadian Patent No. 2,663,650 to Kaminsky. The barrier systems described consists of freeze walls from wells, wax impregnation, grouting from boreholes and freeze walls using conventional hydraulic fracturing to create a fluid flow conduit within the subsurface. Most of the techniques cited are uneconomic due to the extensive number of wells required, others especially those involving hydraulic fracturing, describe the use of hydraulic fracturing in its conventional sense, and such application of hydraulic fracturing of brittle rock to form fractures therein are typically not applicable to ductile formations comprising unconsolidated, weakly cemented sediments. In brittle formations using conventional hydraulic fracturing, the fracture orientation either vertical or horizontal or inclined, and if vertical its azimuth is controlled by the in-situ formation principal stresses, and as such a continuous vertical barrier along a pre-determined azimuth can not be constructed by conventional hydraulic fracturing, and especially not in weakly cemented formations.

Techniques used in hard, brittle rock to form fractures therein are typically not applicable to ductile formations comprising unconsolidated, weakly cemented sediments. The method of controlling the azimuth of a vertical hydraulic planar inclusion in formations of unconsolidated or weakly cemented soils and sediments by slotting the well bore or installing a pre-slotted or weakened casing at a predetermined azimuth has been disclosed. The method disclosed that a vertical hydraulic planar inclusion can be propagated at a pre-determined azimuth in unconsolidated or weakly cemented sediments and that multiple orientated vertical hydraulic planar inclusions at differing azimuths from a single well bore can be initiated and propagated for the enhancement of petroleum fluid production from the formation. See U.S. Pat. No. 6,216,783 to Hocking et al., U.S. Pat. No. 6,443,227 to Hocking et al., U.S. Pat. No. 6,991,037 to Hocking, U.S. Pat. No. 7,404,441 to Hocking, U.S. Pat. No. 7,640,975 to Cavender et al., U.S. Pat. No. 7,640,982 to Schultz et al., U.S. Pat. No. 7,748,458 to Hocking, U.S. Pat. No. 7,814,978 to Steele et al., U.S. Pat. No. 7,832,477 to Cavender et al., U.S. Pat. No. 7,866,395 to Hocking, U.S. Pat. No. 7,950,456 to Cavender et al., U.S. Pat. No. 8,151,874 to Schultz et al. The method disclosed that a vertical hydraulic planar inclusion can be propagated at a pre-determined azimuth in unconsolidated or weakly cemented sediments and that multiple orientated vertical hydraulic planar inclusions at differing azimuths from a single well bore can be initiated and propagated for the enhancement of petroleum fluid production from the formation. It is now known that unconsolidated or weakly cemented sediments behave substantially different from brittle rocks from which most of the hydraulic fracturing experience is founded.

The methods disclosed above find especially beneficial application in ductile rock formations made up of unconsolidated or weakly cemented sediments, in which it is typically very difficult to obtain directional or geometric control over inclusions as they are being formed. Weakly cemented sediments are primarily frictional materials since they have minimal cohesive strength. An uncemented sand having no inherent cohesive strength (i.e., no cement bonding holding the sand grains together) cannot contain a stable crack within its structure and cannot undergo brittle fracture. Such materials are categorized as frictional materials which fail under shear stress, whereas brittle cohesive materials, such as strong rocks, fail under normal stress.

The term “cohesion” is used in the art to describe the strength of a material at zero effective mean stress. Weakly cemented materials may appear to have some apparent cohesion due to suction or negative pore pressures created by capillary attraction in fine grained sediment, with the sediment being only partially saturated. These suction pressures hold the grains together at low effective stresses and, thus, are often called apparent cohesion.

The suction pressures are not true bonding of the sediment's grains, since the suction pressures would dissipate due to complete saturation of the sediment. Apparent cohesion is generally such a small component of strength that it cannot be effectively measured for strong rocks, and only becomes apparent when testing very weakly cemented sediments.

Geological strong materials, such as relatively strong rock, behave as brittle materials at normal petroleum reservoir depths, but at great depth (i.e. at very high confining stress) or at highly elevated temperatures, these rocks can behave like ductile frictional materials. Unconsolidated sands and weakly cemented formations behave as ductile frictional materials from shallow to deep depths, and the behavior of such materials are fundamentally different from rocks that exhibit brittle fracture behavior. Ductile frictional materials fail under shear stress and consume energy due to frictional sliding, rotation and displacement.

Conventional hydraulic dilation of weakly cemented sediments is conducted extensively on petroleum reservoirs as a means of sand control. The procedure is commonly referred to as “Frac-and-Pack.” In a typical operation, the casing is perforated over the formation interval intended to be fractured and the formation is injected with a treatment fluid of low gel loading without proppant, in order to form the desired two winged structure of a fracture. Then, the proppant loading in the treatment fluid is increased substantially to yield tip screen-out of the fracture. In this manner, the fracture tip does not extend further, and the fracture and perforations are backfilled with proppant.

The process assumes a two winged fracture is formed as in conventional brittle hydraulic fracturing. However, such a process has not been duplicated in the laboratory or in shallow field trials. In laboratory experiments and shallow field trials what has been observed is chaotic geometries of the injected fluid, with many cases evidencing cavity expansion growth of the treatment fluid around the well and with deformation or compaction of the host formation.

Weakly cemented sediments behave like a ductile frictional material in yield due to the predominantly frictional behavior and the low cohesion between the grains of the sediment. Such materials do not “fracture” and, therefore, there is no inherent fracturing process in these materials as compared to conventional hydraulic fracturing of strong brittle rocks.

Linear elastic fracture mechanics is not generally applicable to the behavior of weakly cemented sediments. The knowledge base of propagating viscous planar inclusions in weakly cemented sediments is primarily from recent experience over the past ten years and much is still not known regarding the process of viscous fluid propagation in these sediments.

Accordingly, there is a need for a method and apparatus for construction of a vertical continuous barrier to isolate the SAGD system from an outcrop or neighboring depleted low pressure steam chambers.

SUMMARY OF THE INVENTION

The present invention is a method and apparatus for the construction of a subsurface barrier to enable more efficient, more economical and less environmental impact for the enhanced recovery of petroleum fluids from the subsurface by steam and/or solvents typically using a SAGD recovery system, for the recovery of heavy oil and bitumen in situ from a oil sands formation. In one embodiment of this invention, multiple propped vertical inclusions are constructed at various azimuths from a first well and propagate into the oil sand formation and filled with a proppant. The vertical inclusions are propagated to intersect and connect with a second and subsequent wells, on azimuth and depth from the first well. Additional vertical inclusions filled with the same proppant are initiated in the first well at progressively shallower depths but on azimuth with the lower propped inclusions, such that they propagate laterally and vertical into the formation and intersect and coalesce with the lower inclusions, and intersect the second and subsequent wells. If the proppant is water or hydrocarbon swellable rubber beads, then the beads will swell and fill the void space in the inclusions. If the proppant is a ceramic coated with an electrically conductive resin, then electrodes are placed in the wells, and an alternating direction current is passed from the well to its neighboring wells, with the electric current passing through the proppant contained in all of the inclusions, thus heating the inclusion by electrical resistive heating. By electrically resistive heating of the inclusion, the heat hardening resin softens and flows to fill the pore space in the inclusions, with the formation providing an active horizontal closure stress on the inclusions thus consolidating the inclusions, and then the resin hardens to be an impermeable barrier.

In another embodiment multiple propped vertical inclusions are constructed at various azimuths from a first well and propagate into the oil sand formation and filled with a proppant. Vertical inclusions filled with the same proppant are constructed from a second and subsequent wells, on azimuth and depth to intersect and coalesce with the inclusions from the first well. Additional vertical inclusions filled with the same proppant are initiated in the first well at progressively shallower depths but on azimuth with the lower propped inclusions, such that they propagate laterally and vertical into the formation and intersect and coalesce with the lower inclusions. Additional vertical inclusions filled with the same proppant are initiated in the second and subsequent wells at progressively shallower depths but on azimuth with the lower propped inclusions, such that they propagate laterally and vertical into the formation and intersect and coalesce both with the lower inclusion and the inclusions from the first well. If the proppant is water or hydrocarbon swellable rubber beads, then the beads will swell and fill the void space in the inclusions. If the proppant is a ceramic coated with an electrically conductive resin, then electrodes are placed in the wells, and an alternating direction current is passed from the well to its neighboring wells, with the electric current passing through the proppant contained in all of the inclusions, thus heating the inclusion by electrical resistive heating. By electrically resistive heating of the inclusion, the heat hardening resin softens and flows to fill the pore space in the inclusions, with the formation providing an active horizontal closure stress on the inclusions thus consolidating the inclusions, and then the resin hardens to be an impermeable barrier.

In an alternate embodiment, the proppant is a sand or ceramic beads, and low temperature high salinity water is circulated throughout the inclusions and freezes the pore water in the formation, thus creating a freeze wall or barrier. While in another embodiment, the proppant is a sand, and a low viscosity grout is injected into the inclusions and fills the voids of the inclusions, and included in the grout is a time delay setting agent. Alternatively, the low viscosity grout is electrically conductive, and by passing an alternating electric current through the inclusions filled with the grout, heats and thus hardens and sets the grout.

Although the present invention contemplates the formation of vertical propped inclusions which generally extend laterally away from a vertical or near vertical well penetrating an earth formation and in a generally vertical plane, those skilled in the art will recognize that the invention may be carried out in earth formations wherein the fractures and the well bores can extend in directions other than vertical.

Other objects, features and advantages of the present invention will become apparent upon reviewing the following description of the preferred embodiments of the invention, when taken in conjunction with the drawings and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic isometric view of a multiple well system and associated method embodying principles of the present invention, using injection and relief wells;

FIG. 2 is a schematic isometric view of a multiple well system and associated method embodying principles of the present invention, using only injection wells;

FIG. 3 is a schematic isometric view of the multiple well system with a lower inclusion propagating towards a neighboring relief well;

FIG. 4 is a schematic isometric view of the multiple well system with a completed lower inclusion intersecting a neighboring relief well;

FIG. 5 is a schematic isometric view of the multiple well system completed with a lower inclusion, and an upper inclusion propagating towards a neighboring relief well;

FIG. 6 is a schematic isometric view of the multiple well system with completed lower and upper inclusions intersecting a neighboring relief well;

FIG. 7 is a schematic isometric view of the multiple well system with a lower inclusion propagating towards a neighboring injection well;

FIG. 8 is a schematic isometric view of the multiple well system with a completed lower inclusion, and a lower inclusion propagating from the neighboring injection well towards it;

FIG. 9 is a schematic isometric view of the multiple well system with a completed lower inclusion, and an upper inclusion propagating towards a neighboring injection well;

FIG. 10 is a schematic isometric view of the multiple well system with completed lower and upper inclusions.

DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT

Several embodiments of the present invention are described below and illustrated in the accompanying drawings. The present invention is a method and apparatus for the construction of a subsurface barrier to enable more efficient, more economical and less environmental impact for the enhanced recovery of petroleum fluids from the subsurface by steam and/or solvents typically using a SAGD recovery system, for the recovery of heavy oil and bitumen in situ from a oil sands formation. Multiple propped vertical inclusions at various azimuths are constructed from multiple wells into the oil sand formation and filled with a proppant. If the proppant is water or hydrocarbon swellable rubber beads, then the beads will swells and fill the void space in the inclusions. If the proppant is a ceramic coated with an electrically conductive resin, then electrodes are placed in the wells, and an alternating current passes through the electrically conductive proppant contained in the inclusions, thus heating the inclusion by electrical resistive heating. By electrically resistive heating of the inclusion, the heat hardening resin softens and flows to fill the pore space in the inclusions, with the formation providing an active horizontal closure stress on the inclusions thus consolidating the inclusions, and then the resin hardens to result in an impermeable barrier. If the inclusions are only filled with viscous fluid containing no proppant, then provided the injected fluid hasn't set or hardened until after neighboring inclusions are injected, by the use of a time delay agent incorporated into the injected fluid, then upon setting of the fluid a substantially continuous barrier will result.

It is well known that extensive heavy oil reservoirs are found in formations comprising unconsolidated, weakly cemented sediments. Unfortunately, the methods currently used for extracting the heavy oil from these formations require the injection of steam under pressure, such as SAGD, and as such are difficult and often uneconomic if the SAGD well pairs are located in proximity to an outcrop or depleted low pressure steam chambers. Even though the formations contain significant quantities of heavy oil and bitumen, that is basically immobile at initial reservoir conditions, the pore water saturation and permeability of the formation gives rise to reasonably high water mobility. Lean zones within the formation only greatly increase the water mobility, thus giving rise to the need for a barrier to provide a more efficient, less environmental impact and more cost effective recovery system. Operating a SAG) steam chamber at lower pressure gives rise to higher steam oil ratios (SORs) but even more significantly at low steam pressures, the steam may not be able to penetrate horizontal shale layers and thus restrict the height of the steam chamber, giving rise to higher SORs and a significant impact on production. Such impacts can have a significant effect on the overall economics of the SAGD process. Thus there is a need for a vertical continuous barrier to isolate the SAGD system from an outcrop or neighboring depleted low pressure steam chambers. In certain circumstances the barrier will not be exposed to high temperatures if remote from operating SAGD wells, however if the barrier is close to active or depleted steam chambers, the barrier will be require to perform at elevated temperatures.

Representatively illustrated in FIG. 1 is a well system 10 and associated method which embody principles of the present invention. The system 10 is particularly useful for constructing a barrier in a heavy oil or bitumen oil sand formation 14. The formation 14 may comprise unconsolidated and/or weakly cemented sediments for which conventional fracturing operations are not well suited. The term “heavy oil” is used herein to indicate relatively high viscosity and high density hydrocarbons, such as bitumen. Heavy oil is typically not recoverable in its natural state (e.g., without heating or diluting) via wells, and may be either mined or recovered via wells through use of steam and solvent injection, in situ combustion, etc. Gas-free heavy oil generally has a viscosity of greater than 100 centipoise and a density of less than 20 degrees API gravity (greater than about 900 kilograms/cubic meter).

As depicted in FIG. 1, a central vertical well has been drilled into the formation 14 and the well casing 11 has been cemented in the formation 14, and neighboring vertical wells have been drilled into the formation and the well casings 16 have been cemented into the formation 14. The term “casing” is used herein to indicate a protective lining for a wellbore. Any type of protective lining may be used, including those known to persons skilled in the art as liner, casing, tubing, etc. Casing may be segmented or continuous, jointed or unjointed, conductive or non-conductive made of any material (such as steel, aluminum, polymers, composite materials, etc.), and may be expanded or unexpanded, etc.

The central well casing string 11 has expansion devices 12 interconnected therein. The neighboring relief wells casing string 16 has an open section 15 interconnected therein. The open section 15 could be a perforated section of the casing, a screen, slotted liner, etc providing hydraulic connection between the neighboring well and the formation 14. The open section 15 of the well is maintained at a lower pressure and independently of the injected fluid 22 pressure. The expansion devices 12 operate to expand the casing string 11 radially outward and thereby dilate the formation 14 proximate the devices, in order to initiate forming of generally vertical and planar inclusions 18, 19 extending outwardly from the wellbore at various azimuths. Suitable expansion devices for use in the well system 10 are described in U.S. Pat. Nos. 6,216,783, 6,330,914, 6,443,227, 6,991,037, 7,404,441, 7,640,975, 7,640,982, 7,748,458, 7,814,978, 7,832,477, 7,866,395, 7,950,456 and 8,151,874. The entire disclosures of these prior patents are incorporated herein by this reference. Other expansion devices may be used in the well system 10 in keeping with the principles of the invention.

Once the devices 12 are operated to expand the casing string 11 radially outward, fluid 22 is forced into the dilated formation 14 to propagate the inclusions 18, 19 into the formation. It is not necessary for the inclusions 18, 19 to be formed simultaneously. Shown in FIG. 1 is a two (2) wing inclusion well system 10, with two (2) inclusions 18, 19 formed at differing depths. The well system 10 does not necessarily need to consist of two (2) inclusions at differing depths, but could consist of a single height inclusion, also the two (2) wings need not be on the same plane or azimuth, but could vary in azimuth, even to the point of constructing a closed barrier system in plan. The choice of the number of inclusions constructed, their geometry, etc will depend on the application, outcrop geometry and orientation, depleted steam chamber geometry, formation type and/or economic benefit.

Typically, the lower inclusions 18 are constructed first, with each wing of the inclusions 18, 19 injected independently of the others. As the inclusions 18, 19 are propagated into the formation 14, the open section 15 of the on azimuth neighboring relief well acts as a pore pressure sink and thus attracts and accelerates the lateral propagation of the inclusion 18, 19, so as to intersect with the neighboring relief well, and thus stop the lateral propagation of the inclusion. The formation 14, pore space may contain a significant portion of immobile heavy oil or bitumen generally up to a maximum oil saturation of 90%; however, even at these very high oil saturations of 90%, i.e. very low water saturation of 10%, the mobility of the formation pore water is quite high, due to its viscosity and the formation permeability. The open section 15 allows mobile formation pore fluids and the injected fluid 22 to enter the relief well at the open section 15 at a reduced pressure, with the open section 15 being at a lower and independent of the injected fluid 22 pressure. Upon the inclusions reaching the open section 15, its lateral tip propagation will stop. The well system 10 is shown with inclusions 18, 19 constructed at only two depths, this well system 10 is cited as only one example of the invention, since there could be alternate forms of the invention containing numerous of upper inclusions constructed at progressively shallower depths, depending on the formation thickness and the presence of lean zones, the distribution of hydrocarbons within the formation 14, and/or economic benefit.

The injected fluid 22 carries the proppant to the extremes of the inclusions 18, 19. Upon propagation of the inclusions 18, 19 to their required lateral and vertical extent, the thickness of the inclusions 18, 19 may need to be increased by utilizing the process of tip screen out. The tip screen out process involves modifying the proppant loading and/or inject fluid 22 properties to achieve a proppant bridge at the inclusion tips. The injected fluid 22 is further injected after tip screen out, but rather then extending the inclusion laterally or vertically, the injected fluid 22 widens, i.e. thickens, and fills the inclusion from the inclusion tips back to the well bore.

The behavioral characteristics of the injected viscous fluid 22 are preferably controlled to ensure the propagating viscous inclusions maintain their azimuth directionality, such that the viscosity of the injected fluid 22 and its volumetric rate are controlled within certain limits depending on the formation 14, the specific gravity and size distribution of the proppant 20. For example, the viscosity of the injected fluid 22 is preferably greater than approximately 100 centipoise. However, if foamed fluid is used, a greater range of viscosity and injection rate may be permitted while still maintaining directional and geometric control over the inclusions. The viscosity and volumetric rate of the injected fluid 22 needs to be sufficient to transport the proppant 20 to the extremities of the inclusions. The size distribution of the proppant 20 needs to be matched with that of the formation 14. Typical size distribution of the proppant would range from #12 to #20 U.S. Mesh for oil sand formations, with an ideal proppant being sand, ceramic beads, water or hydrocarbon swellable rubber beads, or ceramic beads coated with a electrically conductive resin, of which one particularly suitable conductive resin comprises phenol formaldehyde containing fine graphite particles. Such a resin is heat hardenable at temperatures of around 60° C. or higher, thus capable of mechanically binding the proppant together 21 and filling the voids in the proppant packed inclusions to yield impermeable inclusions.

Depending of the type of proppant used and the method of filling the voids in the inclusions, the next steps in the method will differ. If the proppant is water or hydrocarbon swellable rubber beads, then the beads will swell and fill the void space in the inclusions. If the proppant is a ceramic coated with an electrically conductive resin, then electrodes are placed in the wells, and an alternating direction current is passed between the well to its neighboring wells, with the electric current passing through the proppant contained in all of the inclusions, thus heating the inclusion by electrical resistive heating. By electrically resistive heating of the inclusion, the heat hardening resin softens and flows to fill the pore space in the inclusions, with the formation providing an active horizontal closure stress on the inclusions thus consolidating the inclusions, and then the resin hardens to be an impermeable barrier.

If the proppant is a sand or ceramic beads, and a low temperature barrier is acceptable, then low temperature high salinity water is circulated throughout the inclusions and freezes the fresher pore water in the formation, thus creating a freeze wall or barrier. However, if methane gas is present in the formation, and gas hydrates form in the inclusion pore fluid then the inclusions would freeze and either temporarily or completely stop the recirculation process. In such a case, a freeze barrier would not be appropriate, since the prime benefit of the freeze barrier as described is its thickness, due to the large frozen zone in the formation either side of the inclusions. As an alternate to a freeze barrier, with sand or ceramic bead proppant, a low viscosity grout is injected into the inclusions and fills the voids of the inclusions, and included in the grout is a time delay setting agent. Alternatively, the low viscosity grout is electrically conductive, and by passing an alternating electric current through the inclusions filled with the grout, heats and thus hardens and sets the grout.

The selected range of temperatures that the barrier will be subjected to, depends on its distance from active or depleted steam chambers, the time that the barriers needs to function, the steam pressure of active steaming operations, and the temperatures of the depleted steam chambers. The barriers need to be placed either before active steaming operations have begun, or sufficient distance away to be at substantially initial reservoir stress and pore pressure state, since active thermal stresses and large pore pressure gradients can impact the control of the azimuthal orientation of the propagating inclusions. For a barrier in close proximity to proposed SAGD well pairs, the temperatures it may experience are from 150° C. for low pressure to 275° C. for high pressure steaming operations.

The operating pressure of the process for circulating low temperature coolant, such as high saline water, or the injection of low viscosity grout, would be close to ambient reservoir conditions, due to the proppant packed inclusions having a permeability at least two orders of magnitude greater than the formation, thus allowing circulation or injection to be conducted close to ambient reservoir conditions.

As depicted in FIG. 2, an alternate configure of the well system 10 is shown with all wells being vertical injection wells, drilled into the formation 14 and the well casing 11 has been cemented in the formation 14, and neighboring vertical wells have been drilled into the formation, and the well casings 11 have been cemented into the formation 14. In this configuration, typically the multiple propped vertical inclusions 18 are constructed at various azimuths first from the central well and propagate into the oil sand formation, filled with a proppant, and injection of the propagating fluid 22 is stopped when the inclusion is approximately midway between the central well and its neighboring injection well. The fluid in the lowermost inclusion 18 loses its viscosity over time due to breakers placed in the injected fluid 22. Common breakers consist of enzymes, catalyzed oxidizers, and organic acids. The formation 14, pore space may contain a significant portion of immobile heavy oil or bitumen generally up to a maximum oil saturation of 90%; however, even at these very high oil saturations of 90%, i.e. very low water saturation of 10%, the mobility of the formation pore water is quite high, due to its viscosity and the formation permeability. Thus during propagation of the opposing inclusion 18′ from the neighboring well, the inclusion 18 pore fluid's viscosity is low due to the action of the breaker, then inclusion 18 acts a large pore pressure sink, due to size, relative permeability to the formation, mobility of its fluids and the formation's pore fluids, and hydraulic connection to the central well, resulting in the intersect and coalescence of 18′ and 18 irrespective of slight discrepancies in their azimuthal orientations. Additional vertical inclusions 19 filled with the same proppant are initiated in the central well at progressively shallower depths but on azimuth with the lower propped inclusions, such that they propagate laterally and vertical into the formation and intersect and coalesce with the lower inclusions, since these lower inclusions 18, 18′ act as pore pressure sinks due to their low inclusion pore fluid viscosity from the action of the breakers in the injected fluid 22. Injection of the inclusions 19 are stopped, when the inclusion 19 is approximately midway between the central and neighboring well, and similarly inclusions 19′ are formed to intersect and coalesce with inclusions 18, 18′ and 19, creating a continuous and coalesced inclusions both vertically and laterally.

The formation 14 could be comprised of relatively hard and brittle rock, but the system 10 and method find especially beneficial application in ductile rock formations made up of unconsolidated or weakly cemented sediments, in which it is typically very difficult to obtain directional or geometric control over inclusions as they are being formed.

However, the present disclosure provides information to enable those skilled in the art of hydraulic fracturing, soil and rock mechanics to practice a method and system 10 to initiate and control the propagation of a viscous fluid in weakly cemented sediments, and importantly for the propagating inclusion to intersect and coalesce with earlier placed permeable inclusions and thus form a continuous planar inclusion on a particular azimuth from within a single well or between multiple wells.

The system and associated method are applicable to formations of weakly cemented sediments with low cohesive strength compared to the vertical overburden stress prevailing at the depth of interest. Low cohesive strength is defined herein as no greater than 3 MegaPasca (MPa) plus 0.4 times the mean effective stress (p′) in MPa at the depth of propagation.

c<3 MPa+0.4p′  (1)

where c is cohesive strength in MPa and p′ is mean effective stress in the formation.

Examples of such weakly cemented sediments are sand and sandstone formations, mudstones, shales, and siltstones, all of which have inherent low cohesive strength. Critical state soil mechanics assists in defining when a material is behaving as a cohesive material capable of brittle fracture or when it behaves predominantly as a ductile frictional material.

Weakly cemented sediments are also characterized as having a soft skeleton structure at low effective mean stress due to the lack of cohesive bonding between the grains. On the other hand, hard strong stiff rocks will not substantially decrease in volume under an increment of load due to an increase in mean stress.

In the art of poroelasticity, the Skempton B parameter is a measure of a sediment's characteristic stiffness compared to the fluid contained within the sediment's pores. The Skempton B parameter is a measure of the rise in pore pressure in the material for an incremental rise in mean stress under undrained conditions.

In stiff rocks, the rock skeleton takes on the increment of mean stress and thus the pore pressure does not rise, i.e., corresponding to a Skempton B parameter value of at or about 0. But in a soft soil, the soil skeleton deforms easily under the increment of mean stress and, thus, the increment of mean stress is supported by the pore fluid under undrained conditions (corresponding to a Skempton B parameter of at or about 1).

The following equations illustrate the relationships between these parameters in equations denoted as (2) as follows:

Δu=BΔp

B=(K _(u) −K)/(αK _(u))

α=1−(K/K _(s))  (2)

where Δu is the increment of pore pressure, B the Skempton B parameter, Δp the increment of mean stress, K_(u) is the undrained formation bulk modulus, K the drained formation bulk modulus, α is the Biot-Willis poroelastic parameter, and K_(s) is the bulk modulus of the formation grains. In the system and associated method, the bulk modulus K of the formation for inclusion propagation is preferably less than approximately 5 GPa.

For use of the system 10 and method in weakly cemented sediments, preferably the Skempton B parameter is as follows with p′ in MPa:

B>0.95exp(−0.04p′)+0.008p′  (3)

The system and associated method are applicable to formations of weakly cemented sediments (such as tight gas sands, mudstones and shales) where large entensive propped vertical permeable drainage planes are desired to intersect thin sand lenses and provide drainage paths for greater gas production from the formations. In weakly cemented formations containing heavy oil (viscosity>100 centipoise) or bitumen (extremely high viscosity>100,000 centipoise), generally known as oil sands, propped vertical permeable drainage planes provide drainage paths for cold production from these formations, and access for steam, solvents, oils, and heat to increase the mobility of the petroleum hydrocarbons and thus aid in the extraction of the hydrocarbons from the formation. In highly permeable weak sand formations, permeable drainage planes of large lateral length result in lower drawdown of the pressure in the reservoir, which reduces the fluid gradients acting towards the wellbore, resulting in less drag on fines in the formation, resulting in reduced flow of formation fines into the wellbore.

Proppant is carried by the injected fluid, resulting in a highly permeable planar inclusion. Such proppants are typically clean sand or specialized manufactured particles (generally ceramic in composition), and depending on the size composition, closure stress and proppant type, the permeability of the fracture can be controlled. Water or hydrocarbon swellable rubber beads can swell to twice their initial volume over time, due to their osmotic uptake of water or hydrocarbon. These beads are capable of acting as a barrier even at elevated temperatures. Electrically conductive proppant can consist of ceramics with electrically conductive resin, with a suitable conductive resin comprises phenol formaldehyde containing fine graphite particles. The permeability of the propped inclusions 18 will typically be orders of magnitude greater than the formation 14 permeability, generally at least by two orders of magnitude. As regards the electrical conductivity of the propped inclusions 18, the electrical conductivity needs to be greater than the formation 14 electrical conductivity, but not too great whereas electric energy is lost by excessive short-circuiting between the electrodes, but an optimum value to achieve optimum, efficient and economical resistive heating of the inclusions 18 and the proppant 20, resulting in the resin completely filling the inclusions' voids 21.

The injected fluid 22 varies depending on the application and can be water, oil or multi-phased based gels. Aqueous based fracturing fluids consist of a polymeric gelling agent such as solvatable (or hydratable) polysaccharide, e.g. galactomannan gums, glycomannan gums and cellulose derivatives. The purpose of the hydratable polysaccharides is to thicken the aqueous solution and thus act as viscosifiers, i.e. increase the viscosity by 100 times or more over the base aqueous solution. A cross-linking agent can be added which further increases the viscosity of the solution. The borate ion has been used extensively as a cross-linking agent for hydrated guar gums and other galactomannans. See U.S. Pat. No. 3,059,909 to Wise. Other suitable cross-linking agents are chromium, iron, aluminum, and zirconium (see U.S. Pat. No. 3,301,723 to Chrisp) and titanium (see U.S. Pat. No. 3,888,312 to Tiner et al.). A breaker is added to the solution to controllably degrade the viscous fracturing fluid. Common breakers are enzymes and catalyzed oxidizer breaker systems, with weak organic acids sometimes used.

An enlarged scale isometric view of the system 10 is representatively illustrated in FIG. 3. This view depicts the system 10 during the propagation of only one of the lowermost inclusions 18, to provide a clearer description of the process used to construct the system 10. The viscous fluid propagation process in these sediments involves the unloading of the formation 14 in the vicinity of the tips 23, 24, 25 of the propagating viscous fluid 22, causing dilation of the formation 14, which generates pore pressure gradients towards this dilating zone. As the formation 14 dilates at the tips 23, 24, 25 of the advancing viscous fluid 22, the pore pressure decreases dramatically at the tips, resulting in increased pore pressure gradients surrounding the tips.

The pore pressure gradients at the tips 23, 24, 25 of the inclusion 18 result in the liquefaction, cavitation (degassing) or fluidization of the formation 14 immediately surrounding the tips. That is, the formation 14 in the dilating zone about the tips 23, 24, 25 acts like a fluid since its strength, fabric and in situ stresses have been destroyed by the fluidizing process, and this fluidized zone in the formation immediately ahead of the viscous fluid 22 propagating tips 23, 24, 25 is a planar path of least resistance for the viscous fluid to propagate further. In at least this manner, the system 10 and associated method provide for directional and geometric control over the advancing inclusions 18.

The behavioral characteristics of the injected viscous fluid 22 are preferably controlled to ensure the propagating viscous fluid does not overrun the fluidized zone and lead to a loss of control of the propagating process. Thus, the viscosity of the fluid 22 and the volumetric rate of injection of the fluid should be controlled to ensure that the conditions described above persist while the inclusions 18 are being propagated through the formation 14. The propagation rate of the inclusion 18 due to the injected fluid 22, varies depending on direction, in general due to gravitation effects, the lateral tip 23 propagation rate is generally much greater than the upward tip 24 propagation rate and the downward tip 25 propagation rate. However, these tips 23, 24, 25 propagation rates can change due to heterogeneities in the formation 14, pore pressure gradients especially associated with pore pressure sinks, and stress, stiffness and strength contrasts in the formation 14.

During propagation of the inclusion 18, the pore pressure in the overall formation 14 will rise due to the injection of the fluid 22. As the inclusion 18 propagates, the open section 15 of the neighboring relief well acts as a pore pressure sink and mobile formation pore fluids and injected fluid 22 flows towards 15 as shown by 29. The open section 15 thus attracts and accelerates the lateral tip 23 propagation rate of the inclusion 18. The inclusion 18 grows laterally towards the open section 15, and upon reaching the relief well, the inclusion lateral tip propagation stops.

Referring further to an enlarged scale isometric view of the system 10 is representatively illustrated in FIG. 4. The inclusion 18 has intersected the neighboring relief and its lateral propagation has stopped. By shutting in the neighboring relief well, the inclusion 18 can be thickened if desired by the process of tip screen-out.

Referring further to an enlarged scale isometric view of the system 10 is representatively illustrated in FIG. 5. This view depicts the system 10 during the propagation of only one of the uppermost inclusions 19, to provide a clearer description of the process used to construct the system 10. The lowermost inclusion 18 has been constructed to its final dimension, and the fluid within the inclusion 18 has lost its viscosity due to breakers placed in the injected fluid 22. Common breakers consist of enzymes, catalyzed oxidizers, and organic acids. The formation 14, pore space may contain a significant portion of immobile heavy oil or bitumen generally up to a maximum oil saturation of 90%; however, even at these very high oil saturations of 90%. i.e. very low water saturation of 10%, the mobility of the formation pore water is quite high, due to its viscosity and the formation permeability. Thus during propagation of the uppermost inclusion 19, and provided the lowermost inclusion pore fluid's viscosity is low due to the action of the breaker, then the lowermost inclusion 18 acts a large pore pressure sink, due to size, relative permeability to the formation, mobility of its and the formation's pore fluids, as does the open section 15 in the neighboring relief well.

During propagation of the uppermost inclusion 19, the pore pressure in the overall formation will rise due to the injection of the fluid 22. The lowermost inclusion 18 will act as a pore pressure sink and thus attract and accelerate the downward propagating tip 28, and ensure that the propagating uppermost inclusion 19 intersects and coalesces with the lowermost inclusion 18, even if there are slight discrepancies in their respective azimuthal orientations. Upon coalescence of the downward propagating tip 28 with the lowermost inclusion 18, the tip 28 will stop propagating in the area of coalescence due to leakoff of the injected fluid 22 to the highly permeable pore pressure sink, inclusion 18. As the inclusion 19 further propagates, the open section 15 of the on azimuth neighboring relief well acts as a pore pressure sink and mobile formation pore fluids and injected fluid 22 flows towards 15 as shown by 29. The open section 15 thus attracts and accelerates the lateral tip 26 propagation rate of the inclusion 19. The inclusion 19 grows laterally towards the open section 15, and upon reaching the relief well, the inclusion lateral tip propagation stops. At completion of the injection of fluid 22 in inclusions 19, the system 10 configuration will contain continuous vertical coalescence of inclusions 18 with its respective on azimuth inclusions 19.

Referring further to an enlarged scale isometric view of the system 10 is representatively illustrated in FIG. 6. The inclusion 19 has intersected and coalesced with the lower inclusion 18, and intersected the neighboring relief and thus its lateral propagation has stopped. By shutting in the neighboring relief well, the inclusion 19 can be thickened if desired by the process of tip screen-out.

Referring further to an enlarged scale isometric view of the system 10 is representatively illustrated in FIG. 7 in an alternate configuration. In this alternate configuration, the neighboring well is an injection well and not a relief well as shown earlier in FIG. 3. The neighboring injection well casing string 11 has expansion devices 12 interconnected therein. The lower inclusion 18 is propagating into the formation and the injection fluid 22 flow rate is stopped when the inclusion is approximately midway between the central well and the neighboring injection well. The inclusion 18 can be thickened at this stage by the process of tip screen-out if desired.

Referring further to an enlarged scale isometric view of the system 10 is representatively illustrated in FIG. 8. This view depicts the system 10 during the propagation of the lowermost inclusion 18′ from the neighboring injection well. The lowermost inclusion 18 has been constructed to its final dimension, and the fluid within the inclusion 18 has lost its viscosity due to breakers placed in the injected fluid 22. Common breakers consist of enzymes, catalyzed oxidizers, and organic acids. The formation 14, pore space may contain a significant portion of immobile heavy oil or bitumen generally up to a maximum oil saturation of 90%; however, even at these very high oil saturations of 90%, i.e. very low water saturation of 10%, the mobility of the formation pore water is quite high, due to its viscosity and the formation permeability. Thus during propagation of the lowermost inclusion 18′, and provided the lowermost inclusion pore fluid's viscosity is low due to the action of the breaker, then the lowermost inclusion 18 acts a large pore pressure sink, due to size, relative permeability to the formation, mobility of its and the formation's pore fluids, resulting in the intersect and coalescence of 18′ and 18 irrespective of slight discrepancies in their azimuthal orientations.

Referring further to an enlarged scale isometric view of the system 10 is representatively illustrated in FIG. 9. This view depicts the system 10 during the propagation of only one of the uppermost inclusions 19, to provide a clearer description of the process used to construct the system 10. The lowermost inclusions 18 and 18′ have been constructed to their final dimensions, and the fluid within the inclusions 18 and 18′ have lost its viscosity due to breakers placed in the injected fluid 22. Thus during propagation of the uppermost inclusion 19, and provided the lowermost inclusions pore fluid's viscosity is low due to the action of the breaker, then the lowermost inclusions 18 and 18′ acts as large pore pressure sinks, due to size, relative permeability to the formation, mobility of its and the formation's pore fluids. Thus inclusion 19 intersects and coalesces with inclusions 18 and 18′. The injected fluid 22 flow rate is stopped once the inclusion 19 is approximately midway between the central well and the neighboring injection well.

Referring further to an enlarged scale isometric view of the system 10 is representatively illustrated in FIG. 10. This view depicts the system 10 for the completion of all inclusions, 18, 18′, 19, 19′ showing the coalescence of the inclusions both vertically and laterally.

Finally, it will be understood that the preferred embodiment has been disclosed by way of example, and that other modifications may occur to those skilled in the art without departing from the scope and spirit of the appended claims. 

1. A method of constructing a barrier in a subterranean formation of unconsolidated, weakly cemented sediments, the method comprising the steps of: a) propagating a substantially vertical first inclusion into the formation in a first preferential direction from a substantially vertical central wellbore intersecting the formation; b) when the viscosity of injected fluid in the first inclusion is not high, propagating a substantially vertical second inclusion from a neighboring well in a same but opposite preferential direction as the first inclusion, the second vertical inclusion to intersect and coalesce with the first vertical inclusion in the same formation.
 2. The method of claim 1, wherein the method further includes propagating a plurality of first and second inclusions at varying azimuths.
 3. The method of claim 1, wherein the method further includes propagating a plurality of inclusions propagated from the same wellbores at progressively shallower depths when the viscosity of the injected fluid in the immediate lower inclusion is not high, wherein the inclusions at shallower depths intersect and coalesce with the inclusions immediately beneath on their respective azimuths.
 4. The method of claim 3, wherein the method includes providing a plurality of injection wells and associated inclusions.
 5. The method of claim 1, wherein the inclusions are propagated with a time delay setting grout.
 6. The method of claim 5, wherein the grout is of the sodium silicate group.
 7. The method of claim 5, wherein the grout is a cement based grout.
 8. The method claim 1, wherein the inclusions are propagated with a grout that hardens at elevated temperatures.
 9. The method claim 1, wherein the inclusions are propagated with an electrically conductive grout that hardens at elevated temperatures.
 10. The method of claim 9, wherein an alternating electric current is passed between neighboring wells, and heats and sets the grout by electric resistive heating.
 11. The method of claim 1, wherein the inclusions are propagated with a fluid carrying a proppant.
 12. The method of claim 11, wherein the inclusions are propagated with a water based fluid.
 13. The method of claim 12, wherein the proppant includes water swellable rubber particles of a size ranging from #4 to #100 U.S. mesh.
 14. The method of claim 11, wherein the inclusions are propagated with a hydrocarbon based fluid.
 15. The method of claim 14, wherein the proppant includes hydrocarbon swellable rubber particles of a size ranging from #4 to #100 U.S. mesh.
 16. The method of claim 11, wherein the proppant particles are of a size ranging from #4 to #100 U.S. mesh are sand or ceramic beads substantially coated with an electrically conductive resin.
 17. The method of claim 16, wherein the resin is phenol formaldehyde containing fine graphite particles and is heat hardenable, with resin present in an amount sufficient to fill the voids in the inclusions.
 18. The method of claim 17, wherein an alternating electric current is passed between neighboring wells and heats the proppant by electric resistive heating.
 19. The method of claim 11, wherein the proppant is a sand or ceramic beads of a size ranging from #4 to #100 U.S. mesh.
 20. The method of claim 19, wherein cold high saline water is circulated through the inclusions to freeze formation pore water fluids.
 21. The method of claim 19, wherein low viscosity grout is injected into the inclusions with a time delay setting agent.
 22. The method of claim 21, wherein the grout is sodium silicate.
 23. The method of claim 21, wherein the grout is a cement based grout.
 24. The method claim 19, wherein an electrically conductive grout is injected into the inclusions and hardens at elevated temperatures.
 25. The method of claim 21, wherein an alternating electric current is passed between neighboring wells, and heats and sets the grout by electric resistive heating. 26-50. (canceled)
 51. The method of claim 1, wherein the formation has a Skempton B parameter greater than 0.95 exp(−0.04 p′)+0.008 p′, where p′ is a mean effective stress in MPa at the depth of the first inclusion and the water saturation in the formation pores is greater or equal to 10%. 